Hydrocarbons sometimes exist in a formation but cannot flow readily into the well because the formation has very low permeability. In order for hydrocarbons to travel from the formation to the wellbore there must be a flow path from the formation to the wellbore. This flow path is through the formation rock and has pores of sufficient size and number to allow a conduit for the hydrocarbons to move through the formation. In some subterranean formations containing hydrocarbons, the flow paths are of low incidence or occurrence and/or size that efficient hydrocarbon recovery is hampered.
With respect to wells that previously produced satisfactorily, a common reason for a decline in oil and gas production from a particular formation is damage to the formation that plugs the rock pores and impedes the flow of oil to the wellbore and ultimately to the surface.
Well stimulation refers to the various techniques employed to improve the permeability of a hydrocarbon-bearing formation. One common well stimulation technique is fracturing. Thickened fluids have applications in hydraulic fracturing and in other well stimulation techniques known to one of ordinary skill in the art. Hydraulic fracturing is a method of using pump rate and hydraulic pressure to fracture or crack a subterranean formation thereby creating a relatively large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. Once the crack or cracks are made, high permeability proppant, relative to the formation permeability, is typically pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons. When an acid is used in the fracturing fluid to increase or restore permeability to the formation, the treatment is term “acid fracturing” or “acid frac”.
Conventionally, aqueous fracturing fluids have had their viscosities increased by incorporating hydratable polymers therein (e.g. polysaccharides), where some polymers may be crosslinked to increase viscosity even further. Recently it has been discovered that aqueous drilling and treating fluids may be gelled or have their viscosity increased by the use of non-polymeric viscoelastic surfactants (VES). These VES materials are in many cases advantageous over the use of polymer gelling agents used in the past in that they are comprised of low molecular weight surfactants rather than high molecular polymers whereby polymer accumulations (e.g. polymeric filter cake) can be avoided. Polymeric filter cakes formed on and within the formation can result in damage to the formation when the polymeric filter cakes are removed prior to hydrocarbon production, and this damage may result in reduced production of hydrocarbons. In contrast, viscoelastic type surfactants generate viscosity in aqueous fluids by forming unique elongated micelle arrangements. These unique arrangements have often been referred to as worm-like or rod-like micelles structures. Additionally, VES gelled aqueous fluids may exhibit very high viscosity at very low shear rates and under static conditions. It has been found that generally VES fluids do not damage formations to the extent that polymer gelled fluids do, although recent investigations have discovered that VES-gelled fluids may also damage formations to some extent upon their removal.
Little progress has been made toward developing internal breaker systems for the non-polymeric VES-based gelled fluids. Conventionally, VES gelled fluids have relied only on “external” or “reservoir” conditions for viscosity reduction (breaking) and VES fluid removal (clean-up) during hydrocarbon production. Additionally, over the past decade it has been found that reservoir brine dilution has only a minor, if any, breaking effect of VES gel within the reservoir.
Instead, only one reservoir condition is primarily and conventionally relied on for VES fluid viscosity reduction (gel breaking or thinning), and that has been the rearranging, disturbing, and/or disbanding of the VES worm-like micelle structure by contacting the hydrocarbons within the reservoir, more specifically contacting and mixing with crude oil and condensate hydrocarbons, as described in U.S. Pat. No. 5,964,295. In one non-limiting embodiment, it is believed that the gel or increased viscosity is imparted to the aqueous fluid by the worm-like or rod-like micelles becoming entangled with one another.
However, in many gas wells and in cases of excessive displacement of crude oil hydrocarbons from the reservoir pores during a VES gel treatment, results have shown many instances where VES fluid in portions of the reservoir are not broken or are incompletely broken resulting in formation damage (hydrocarbon production impairment). Contacting and breaking the viscous micelle-based fluid by reservoir hydrocarbons in all parts of the reservoir is not always effective. One viable reason is the exceptionally high viscosity that VES fluid can exhibit at very low shear rates and static conditions which makes the fluid difficult to move and remove from porous media (i.e. the pores of the reservoir). Hydrocarbon producing reservoirs typically have heterogeneous permeability, where VES fluid within the less permeable portions of the reservoir may be even more difficult to move and cleanup. The very high viscosity at very low shear rates can prevent uniform contacting and breaking of viscous VES fluid by the reservoir hydrocarbons. Channeling and by-passing of viscous VES fluid often occurs that results in impaired hydrocarbon production. In such cases post-treatment clean-up fluids composed of either aromatic hydrocarbons, alcohols, surfactants, mutual solvents, and/or other VES breaking additives have been pumped within the VES treated reservoir in order to try and break the VES fluid for removal. However, placement of clean-up fluids is problematic and normally only some sections of the reservoir interval are cleaned up, leaving the remaining sections with unbroken or poorly broken VES gelled fluid that impairs hydrocarbon production.
Because of this phenomenon and other occasions where reliance on external factors or mechanisms has failed to clean-up the VES fluid from the reservoir during hydrocarbon production, or in cases where the external conditions are slow acting (instances where VES breaking and clean-up takes a long time, such as several days up to possibly months) to break and then produce the VES treatment fluid from the reservoir, and where post-treatment clean-up fluids (i.e. use of external VES breaking solutions) are inadequate in removing unbroken or poorly broken VES fluid from all sections of the hydrocarbon bearing portion of the reservoir, there has been an increasing and important industry need for VES fluids to have internal breakers. Desirable internal breakers that should be developed include breaker systems that use products that are incorporated within the VES-gelled fluid that are activated by downhole temperature or another mechanism that will allow a controlled rate of gel viscosity reduction over a rather short period of time of about 1 to 16 hours or so, similar to gel break times common for conventional polymeric fluid systems.
A challenge has been that VES-gelled fluids are not comprised of polysaccharide polymers that are easily degraded by use of enzymes or oxidizers, but are comprised of surfactants that associate and form viscous rod- or worm-shaped micelle structures that exhibit very high apparent viscosity at very low fluid shear rates. Conventional enzymes and oxidizers have not been found to act and degrade the surfactant molecules or the viscous micelle structures they form. It is still desirable, however, to provide some mechanism that relies on and uses internal phase breaker components that will help assure complete viscosity break of VES-gelled fluids.
It would be desirable if a viscoelastic surfactant-based system could have the performance properties similar to or better than polymeric fluid for well treatment, particularly fracturing, but still be less damaging to the formation permeability and fracture conductivity common to VES treatment fluids. It would be even more desirable if a VES fluid system could have performance properties of polymeric fluid for well treatment, but additionally have superior clean-up character to conventional VES fluids used for well treatments, particularly fracturing. It would also be advantageous if a composition and method could be devised to overcome some of the problems in the conventional fracturing methods and fluids.